Tight Oil and Oil Sands Versus Small Deep Water Developments

This post which is based on results from earlier research and analytic work posted on The Oil Drum, Fractional Flow and not least in recent (private) discussions with other international acknowledged experts present some facts and observations about developments of tight oil (which to some extent also applies to oil sands) versus small deep water discoveries*.

*Small deep water discoveries are here meant discoveries with Estimated Ultimate Recovery (EUR) below 100 Million Barrels of Oil Equivalents (MBOE).

Figure 1: Chart above shows relative developments in annualized yield curves (lh scale) of oil for so-called elephants (Norwegian deep water discoveries estimated to hold ultimate recoverable reserves (EUR) above 1,000 million barrels with crude oil [red lines]).
Small discoveries (Norwegian deep water discoveries estimated to hold ultimate recoverable reserves (EUR) below 100 million barrels with crude oil, [green lines]).
The reference tight oil well for Bakken [violet lines].
The cumulative versus time is plotted against the rh scale.
Note also the short high flow life cycles of small deep water developments and tight oil.

One big takeaway from the chart above is that both developed small deep water discoveries and tight oil wells have steep decline rates and short high flow life cycles. These are now the major sources that offset declines from the bigger, heavily depleted legacy fields (with long productive life cycles) and provide any growth in global oil supplies.

 

A tight oil well recovers its oil (EUR) at a relatively slower rate than a small deep water development. This does not tell the full story as the realities now facing the companies like their size, risk appetites, the composition of their portfolios, capital structure and financial situation may be decisive at how they employ their available capital.

Once tight oil acreage is held by production the company is free to develop it at its own pace and respond to market conditions and available cash.

Big International Oil Companies (IOC’s) are from their capital structure used to long and capital intensive lead times. The scale makes a material difference and IOC’s expect large revenue and net cash flows against their technical manpower commitments, reflecting the need to cover a lot of overhead.

• Companies that both hold prolific tight oil acreage (thus the acreage acquisition is sunk cost) in North America (Bakken, Eagle Ford and others) and have deep water discoveries in their portfolios, will now, and using point forward approaches, give priority to tight oil wells (and oil sands) due to predictability and scalability (staged investments, CAPEX flexibility).
• Small, deep water developments have proven to be associated with high reservoir risks and high capital commitments.
• From the start of the investment until it is grossly recovered it takes normally 3 – 4 years for a small Norwegian deep water discovery, if it produces as expected.
• For the Bakken reference tight oil well it takes around 2 years from the well is spudded until the investment is grossly recovered.
  Taxation, royalties, OPerational EXpenses (OPEX), debt services, general and administration etc.  will extend the actual recovery periods of the investments.
• Companies are CAPital EXpenditure (CAPEX) constrained and will favor the developments of sources with the least associated risk that simultaneously offers good returns and capital flexibility.
• Companies and their CEO’s, like Statoil’s Lund (links to text in Norwegian, try Google translate), now states that their focus will shift from barrels to profitability. Recent developments of several of the small Norwegian deep water discoveries prove to yield substantially below what was expected when these were sanctioned. The effects from this is (at best) increased break even costs and extended recovery periods (ignoring taxation effects) for the employed capital.

Typically the development of a small deep water discovery in Norway costs around $800 – $1,000 Million and normally takes a couple of years from being sanctioned until it starts to flow.

A tight oil well in Bakken now costs around $9 Million and from spudding until it flows it normally takes 4 – 6 months.

Figure 2: Chart above shows the break even price on a point forward (partial cycle) basis for a reference (average) well in the Bakken formation in North Dakota at some discount rates.
At a realized oil price of $90/Bbl the Internal Rate of Return (IRR) on a point forward basis was estimated at around 22%. (Which is good!)
Estimates do not include costs for debt services and income from natural gas/NGPL sales which now averages a gross of $3/Bbl. Entrance costs (acquisition costs for acreage and/or companies) are NOT included in the estimates presented in the chart above.
Estimates shown are NOT full cycle break even costs.

By including the acquisition costs the full cycle break even price moves higher. For a company holding acreage (acquisition costs will be considered sunk costs) thus the manufacturing of additional wells can be considered on a point forward basis (partial cycle).

Companies that both hold tight oil acreage and have small deep water discoveries in their portfolios will find that these developments are in competition with each other for CAPEX. The developments that show the greatest prospects for returns, best predictability and offers investments scaling (employment of capital) is likely to see most of the companies’ CAPEX flow their way. This consideration is now believed to weigh more heavily in the near term as many companies will find their future CAPEX under pressure, also from targeting financial performance.

NOTE: For some companies (IOC’s) that acquired their tight oil acreage in Bakken/Eagle Ford through acquisitions of other companies, forecasts now for the full cycle profitability (return) are slightly negative.

Rigzone recently touched on this issue in this article.

The main take away from this post is that new global oil supplies increasingly come from more expensive (as in technically demanding), short cycle, rapidly declining sources and that there are considerable risks associated with some of these sources. Several oil companies are now struggling with growing their supplies (barrels), high debt overhang, declining profitability and cash flows.

At the other end a growing number of consumers find it harder to afford the higher prices required by the oil companies to develop oil supplies from more exotic and distant sources.

The oil companies apparently are also confronted with an insurmountable task of getting this message across to all affected.

What has been presented in this post raises some interesting questions/observations:

• Small, deep water developments and tight oil are now major sources to offset declines from heavily depleted legacy fields and provide any growth in global oil supplies. Common for these two sources are that they have steep decline rates.
• Tight oil appears now to be the last frontier to be tapped into and has in recent years seen improved understandings, enhanced extraction technologies, offers good predictability and CAPEX flexibility. However tight oil can not become a global long term supply solution and may at best be viewed as a temporary bridge.
• Developments of small deep water discoveries now appear to come with more associated risks than tight oil.
• The portfolio of conventional oil resources (providing low cost oil) appears to have been exhausted leaving to the exploitation of more expensive and exotic sources.

What credible and sustainable oil sources will there be after tight oil (and oil sands)?

Any Arctic sources for supplies is still decades into the future, are expensive and logistical demanding (market access).

Both small, deep water developments and tight oil have short high flow life cycles, very steep decline rates which makes it harder and harder to create growth in global oil supplies (The Red Queen effect).

High (and increasing) CAPEX towards tight oil developments and recent year’s dismal results (with a few exceptions) from exploration for conventional sources may thus lend credence to Art Berman’s reference to the tight oil phenomenon as a “retirement party”.

Fractional Flow